LILIS ENERGY, INC. - FORM 10-Q

Attached files

file	filename
EX-31.1 - CERTIFICATIONS PURSUANT TO SECTION 302 OF SARBANES OXLEY ACT OF 2002 - LILIS ENERGY, INC.	f10q0311ex31i_recovery.htm
EX-31.2 - CERTIFICATIONS PURSUANT TO SECTION 302 OF SARBANES OXLEY ACT OF 2002 - LILIS ENERGY, INC.	f10q0311ex31ii_recovery.htm
EX-32.2 - CERTIFICATIONS PURSUANT TO SECTION 906 OF SARBANES OXLEY ACT OF 2002 - LILIS ENERGY, INC.	f10q0311ex32ii_recovery.htm
EX-32.1 - CERTIFICATIONS PURSUANT TO SECTION 906 OF SARBANES OXLEY ACT OF 2002 - LILIS ENERGY, INC.	f10q0311ex32i_recovery.htm

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

_______________

FORM 10-Q

_______________

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2011

o TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ______to______.

RECOVERY ENERGY, INC.

(Exact name of registrant as specified in Charter)

NEVADA		333-152571		74-3231613
(State or other jurisdiction of incorporation or organization)		(Commission File No.)		(IRS Employee Identification No.)

1515 Wynkoop Street, Suite 200

Denver, CO 80202

(Address of Principal Executive Offices)

_______________

1 (888) 887-4449

(Issuer Telephone number)

_______________

Check whether the issuer (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the issuer was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every

Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Yes ¨ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company filer. See definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Exchange Act (Check one):

Large Accelerated Filer o Accelerated Filer o Non-Accelerated Filer o Smaller Reporting Company x

Indicate by check mark whether the registrant is a shell company as defined in Rule 12b-2 of the Exchange Act.

Yes o No x

State the number of shares outstanding of each of the issuer’s classes of common equity, as of May 16, 2011: 62,483,758 shares of Common Stock.

Recovery Energy, Inc.

INDEX

PART I– FINANCIAL INFORMATION

Item 1.	Financial Statements (Unaudited)
	Consolidated Balance Sheets as of March 31, 2011 and December 31, 2010	1
	Consolidated Statements of Operations for the Three Months Ended March 31, 2011 and 2010	3
	Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2011 and 2010	4
	Notes to Consolidated Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition	20
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	31
Item 4T.	Control and Procedures	31

PART II– OTHER INFORMATION

Item 1.	Legal Proceedings	32
Item 1A.	Risk Factors	32
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	32
Item 3.	Defaults Upon Senior Securities	32
Item 4.	Submission of Matters to a Vote of Security Holders	32
Item 5.	Other Information	32
Item 6.	Exhibits and Reports on Form 8-K	32

SIGNATURES

Part 1. Financial Information

Item 1. Financial Statements

RECOVERY ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	March 31,			December 31,
	2011			2010
Assets
Current Assets
Cash	$	2,111,340		$	5,528,744
Restricted cash		1,998,821			1,150,541
Accounts receivable		1,645,985			857,554
Prepaid assets		167,682			27,772
Total current assets		5,923,828			7,564,611

Oil and gas properties (full cost method), at cost:
Undeveloped properties		48,530,863			33,605,594
Developed properties		27,779,396			26,307,975
Wells in progress		2,041,787			1,219,397
Total oil and gas properties		78,352,046			61,132,966

Less accumulated depreciation, depletion and amortization		(6,062,443	)		(5,008,606	)
Net oil and gas properties		72,289,603			56,124,360

Other assets
Office equipment, net		57,517			56,236
Prepaid advisory fees		878,127			979,449
Deferred financing costs, net		4,485,429			3,211,566
Restricted cash and deposits		185,776			185,707
Total other assets		5,606,849			4,432,958

TOTAL ASSETS	$	83,820,280		$	68,121,929

The accompanying notes are an integral part of these consolidated financial statements

RECOVERY ENERGY, INC.

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	March 31,			December 31,
	2011			2010
Liabilities and Shareholders' Equity
Current Liabilities
Accounts payable	$	1,095,247		$	968,295
Liabilities from price risk management		876,752			398,840
Related party payable		12,955			11,638
Accrued expenses		1,370,857			1,540,592
Short term note payable		270,410			208,881
Total current liabilities		3,626,221			3,128,246

Asset retirement obligation		529,506			507,280
Term note payable		19,773,173			20,229,801
Convertible notes payable, net of discount		5,712,057			-
Derivative liability		2,783,000			-
Total long term liabilities		28,797,736			20,737,081

Total liabilities		32,423,957			23,865,327
Commitments and Contingencies – Note 7

Common Stock Subject to Redemption Rights, $0.0001 par value; 0 and 42,500 shares issued and outstanding as of		-			86,258
March 31, 2011 and December 31, 2010, respectively

Shareholders’ Equity
Common stock, $0.0001 par value: 100,000,000 shares authorized;
62,483,758 and 57,814,369 shares issued and outstanding (excluding 0 and 42,500 shares subject to redemption) as of March 31, 2011 and December 31, 2010, respectively		6,248			5,781
Additional paid in capital		101,830,226			90,861,527
Accumulated deficit		(50,440,151	)		(46,696,964	)
Total other shareholders' equity		51,396,323			44,170,344

TOTAL LIABILITIES, COMMON STOCK SUBJECT TO REDEMPTION RIGHTS AND SHAREHOLDERS’ EQUITY	$	83,820,280		$	68,121,929

The accompanying notes are an integral part of these consolidated financial statements

RECOVERY ENERGY, INC.

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)


	Three Months Ended March 31,
	2011			2010

Revenue
Oil sales	$	1,801,814		$	622,595
Gas sales		108,829			-
Operating fees		8,228			1,125
Realized loss on hedges		(167,284	)		-
Price risk management activities		(477,912	)		(133,369	)

Total revenues		1,273,675			490,351

Costs and expenses
Production costs		446,985			121,877
Production taxes		202,299			35,488
General and administrative (includes non-cash expense of $0.7 million and $1.9 million , respectively)		1,600,594			2,343,321
Depreciation, depletion, amortization and accretion		1,075,930			231,917

Total costs and expenses		3,325,808			2,732,603

Loss from operations		(2,052,133	)		(2,242,252	)

Unrealized gain on lock-up		1,115			15,209
Interest expense and financing costs (includes non-cash expense of $0.8 million and $0.5 million, respectively)		(1,692,169	)		(593,672	)

Net loss	$	(3,743,187	)	$	(2,820,715	)

Net loss per common share
Basic and diluted	$	(0.06	)	$	(0.24	)

Weighted average shares outstanding:
Basic and diluted		59,112,825			11,711,037

The accompanying notes are an integral part of these consolidated financial statements

RECOVERY ENERGY, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Three Months Ended March 31,
	2011			2010

Cash flows from operating activities:
Net loss	$	(3,743,187	)	$	(2,820,714	)
Adjustments to reconcile net loss to net cash used in operating activities:
Stock issued for services		126,483			-
Stock based compensation		546,530			1,106,437
Changes in the fair value of derivatives		477,912			133,369
Compensation expense recognized for assignment of overrides		-			826,510
Amortization of deferred financing costs		837,376			466,174
Depreciation, depletion, amortization and accretion		1,075,930			231,917
Changes in operating assets and liabilities:
Accounts receivable		(788,431	)		(326,561	)
Other assets		(83,072	)		9,908
Accounts payable		117,271			208,314
Restricted cash		(848,280	)		(18,561	)
Related party payable		10,998			(56,214	)
Accrued expenses		(169,735)			44,089
Net cash used in operating activities		(2,440,205)			(195,332)

Cash flows from investing activities:
Additions of producing properties and equipment (net of purchase price adjustments)		-			(48,421	)
Acquisition of undeveloped properties		(8,416,874	)		(10,313,184	)
Drilling capital expenditures		(2,281,487	)		-
Additions of office equipment		(13,472	)		(501	)
Investment in operating bonds		(69	)		(165	)
Net cash used in investing activities		(10,711,902	)		(10,362,271	)

Cash flows from financing activities:
Proceeds from sale of common stock, units and exercise of warrants		2,129,801			300,000
Proceeds from debt		8,000,000			10,500,000
Repayment of debt		(395,098	)		(178,750	)
Net cash provided by financing activities		9,734,703			10,621,250

Change in cash and cash equivalents		(3,417,404	)		63,647
Cash and cash equivalents at beginning of period		5,528,744			108,400

CASH AND CASH EQUIVALENTS AT END OF PERIOD	$	2,111,340		$	172,047

The accompanying notes are an integral part of these consolidated financial statements

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF MARCH 31, 2011

(UNAUDITED)

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

The accompanying unaudited interim consolidated financial statements were prepared by Recovery Energy, Inc. (“Recovery” or the “Company”) in accordance with generally accepted accounting principles (“GAAP”) in the United States applicable to interim financial statements and reflect all normal recurring adjustments which are, in the opinion of management, necessary to provide a fair statement of the results of operations and financial position for the interim periods. The results of operations for the interim periods are not necessarily indicative of the results to be expected for the full fiscal year. Such financial statements conform to the presentation reflected in the Company's Annual Report on Form 10-K filed with the Securities and Exchange Commission (the "SEC") for the year ended December 31, 2010. The current interim period reported herein should be read in conjunction with the financial statements and summary of significant accounting policies and notes included in the Company's Annual Report on Form 10-K for the year ended December 31, 2010. Certain amounts in the 2010 consolidated financial statements have been reclassified to conform to the 2011 consolidated financial statement presentation. Such reclassifications had no effect on net income.

Principles of Consolidation

The accompanying consolidated financial statements include Recovery Energy, Inc. and its wholly−owned subsidiaries Recovery Oil and Gas, LLC, and Recovery Energy Services, LLC. All intercompany accounts and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of oil and gas reserves, assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate our estimates on an on-going basis and base our estimates on historical experience and on various other assumptions we believe to be reasonable under the circumstances. Although actual results may differ from these estimates under different assumptions or conditions, we believe that our estimates are reasonable. Our most significant financial estimates are associated with our estimated proved oil and gas reserves as well as valuation of common stock used in issuances of common stock, options and warrants and the valuation of the conversion rights related to the convertible notes payable.

Liquidity

Since inception, we have raised approximately $72 million in cash generally through private placements of debt and equity securities. Although we have a flexible capital program for 2011, we cannot give assurances that our current working capital, our cash flow from operations or any available borrowings will be sufficient to fund our anticipated capital expenditures. If our existing and potential sources of liquidity through operating cash flows and cash contributions from joint venture participants are not sufficient to undertake our planned capital expenditures, we may be required to alter our drilling program, pursue additional joint ventures with third parties, sell interests in one or more of our properties or sell equity or debt securities. If we are not successful in obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable to us, we would be required to curtail our expenditures, restructure our operations, sell properties on terms which otherwise may not be as favorable and/or curtail our planned exploration and drilling program.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF MARCH 31, 2011

(UNAUDITED)

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Cash and Cash Equivalents

Cash and cash equivalents include cash in banks and highly liquid debt securities that have original maturities of three months or less. Financial instruments that potentially subject the Company to concentration of credit risk consist primarily of cash deposits.

Restricted Cash

Restricted cash consists of severance and ad valorem tax proceeds which are payable to various tax authorities, and are restricted pursuant to our loan agreements, and certain proceeds from the Company’s convertible notes payable proceeds which are restricted to capital expenditures on certain leasehold interests.

Accounts Receivable

The Company records estimated oil and gas revenue receivable from third parties at its net revenue interest. The Company also reflects costs incurred on behalf of joint interest partners in accounts receivable. Management periodically reviews accounts receivable amounts for collectability and records its allowance for uncollectible receivables under the specific identification method.

Concentration of Credit Risk

The Company's cash equivalents and short-term investments are exposed to concentrations of credit risk. The Company manages and controls this risk by investing these funds with major financial institutions. The Company may at times have balances in excess of the federally insured limits.

The Company's receivables are comprised of oil and gas revenue receivables and joint interest billings receivable. The amounts are due from a limited number of entities. Therefore, collectability is dependent upon the general economic conditions of the few purchasers and joint interest owners. The receivables are not collateralized. However, to date the Company has had minimal bad debts.

Oil and Gas Producing Activities

The Company follows the full cost method of accounting for oil and gas operations whereby all costs related to the exploration and development of oil and gas properties are initially capitalized into a single cost center ("full cost pool"). Such costs include land acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling directly related to acquisition and exploration activities. Proceeds from property sales are generally credited to the full cost pool, with no gain or loss recognized, unless such a sale would significantly alter the relationship between capitalized costs and the proved reserves attributable to these costs. A significant alteration would typically involve a sale of 25% or more of the proved reserves related to a single full cost pool.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF MARCH 31, 2011

(UNAUDITED)

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Depletion of exploration and development costs and depreciation of production equipment is computed using the units-of-production method based upon estimated proved oil and gas reserves. Costs included in the depletion base to be amortized include (a) all proved capitalized costs including capitalized asset retirement costs net of estimated salvage values, less accumulated depletion, (b) estimated future development cost to be incurred in developing proved reserves; and (c) estimated dismantlement and abandonment costs, net of estimated salvage values, that have not been included as capitalized costs because they have not yet been capitalized as asset retirement costs. The costs of unproved properties are withheld from the depletion base until it is determined whether or not proved reserves can be assigned to the properties. The properties are reviewed quarterly for impairment. When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to costs subject to depletion calculations.

Estimated reserve quantities and future net cash flows have the most significant impact on the Company because these reserve estimates are used in providing a measure of the Company's overall value. These estimates are also used in the quarterly calculations of depletion, depreciation and impairment of the Company's proved properties.

Estimating accumulations of gas and oil is complex and is not exact because of the numerous uncertainties inherent in the process. The process relies on interpretations of available geological, geophysical, engineering and production data. The extent, quality and reliability of this technical data can vary. The process also requires certain economic assumptions, some of which are mandated by the SEC, such as gas and oil prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The accuracy of a reserve estimate is a function of the quality and quantity of available data; the interpretation of that data; the accuracy of various mandated economic assumptions; and the judgment of the persons preparing the estimate.

The optimal method of determining proved reserve estimates is based upon a decline analysis method, which consists of extrapolating future reservoir pressure and production from historical pressure decline and production data. The accuracy of the decline analysis method generally increases with the length of the production history. Most of the Company's wells have been producing for a period of less than six years and for some, less than a year. Because of this short production history, other generally less accurate methods such as volumetric analysis and analogy to the production history of wells of ours and other operators in the same reservoir were used in conjunction with the decline analysis method to determine the Company's estimates of proved reserves including developed producing, developed non-producing and undeveloped. As the Company's wells are produced over time and more data is available, the estimated proved reserves will be re-determined at least on a quarterly basis in accordance with applicable rules established by the SEC and may be adjusted based on that data.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF MARCH 31, 2011

(UNAUDITED)

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Depletion and Impairment of Proved Oil and Gas Properties

When proved reserves are assigned or the property is considered to be impaired, the cost of the property or the amount of the impairment is added to the full cost pool and becomes subject to depletion calculations. The cost of acquiring and evaluating unproved properties are initially excluded from depletion calculations. Capitalized costs, together with the costs of production equipment, are depleted and amortized on the unit-of-production method based on the estimated proved reserves. For this purpose, we convert our petroleum products and reserves to a common unit of measure. For depletion and depreciation purposes, relative volumes of oil and gas production and reserves are converted at the energy equivalent rate of six thousand cubic feet of natural gas to one barrel of crude oil. Under the full cost method of accounting, capitalized oil and gas property costs less accumulated depletion and net of deferred income taxes may not exceed an amount equal to the present value, discounted at 10%, of estimated future net revenues from proved oil and gas reserves plus the cost of unproved properties not subject to amortization (without regard to estimates of fair value), or estimated fair value, if lower, of unproved properties that are subject to amortization. Should capitalized costs exceed this ceiling, an impairment is recognized. The present value of estimated future net revenues was computed by applying a twelve month average of the first day of the month price of oil and gas to estimated future production of proved oil and gas reserves as of period-end, less estimated future expenditures to be incurred in developing and producing the proved reserves (assuming the continuation of existing economic conditions), less any applicable future taxes.

There were no impairment charges recognized for the three month periods ended March 31, 2011 and 2010.

Wells in Progress

Wells in progress at March 31, 2011 represent the costs associated with wells that have not reached total depth or been completed as of period end. They are classified as wells in progress and withheld from the depletion calculation and the ceiling test. The costs for these wells are then transferred to proved property when the wells reach total depth and are cased and the costs become subject to depletion and the ceiling test calculation in future periods. At March 31, 2011, the Company had commenced drilling on one well and had two wells awaiting completion.

Deferred Financing Costs

For the three months ended March 31, 2011, the Company recorded deferred financing costs of approximately $2,000,000 related to the extension of its term notes and the closing of its convertible notes. Deferred financing costs include origination (warrants issued and overriding royalty interests assigned to our lender), and legal and engineering fees incurred in connection with the Company's credit facility, which are being amortized over the term of the credit facility. The Company recorded amortization expense of approximately $837,000 for the three months ended March 31, 2011.

Prepaid Advisory Fees

The Company had prepaid financial advisory fees of approximately $878,000 as of March 31, 2011. The prepaid fees were paid with non-cash consideration (shares of our common stock and warrants exercisable for shares of our common stock issued to our financial advisors) initially totaling approximately $1,234,000. The amount is being amortized over the term of the underlying agreement. The Company amortized approximately $101,000 in prepaid fees for the three months ended March 31, 2011.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF MARCH 31, 2011

(UNAUDITED)

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Impairment of Long-lived Assets

The Company accounts for the impairment and disposition of long-lived assets (other than the full cost pool) in accordance with ASC 360, Impairment or Disposal of Long-Lived Assets. ASC 360 requires that the Company’s long-lived assets be assessed for potential impairment in their carrying values whenever events or changes in circumstances indicate such impairment may have occurred. An impairment charge to current operations is recognized when the estimated undiscounted future net cash flows of the asset are less than its carrying value. Any such impairment is recognized based on the differences in the carrying value and estimated fair value of the impaired asset. No impairment was recorded during the three month periods ended March 31, 2011 and 2010.

Fair Value of Financial Instruments

The Company's financial instruments, other than the derivative instrument discussed separately, including cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities are carried at cost, which approximates fair value due to the short-term maturity of these instruments. Additionally, the recorded value of the Company's long-term debt approximates its fair value as it bears interest at variable rates over the term of the loan.

Commodity Derivative Instrument

The Company has entered into commodity derivative contracts, as described below. The Company has utilized swaps to reduce the effect of price changes on a portion of our future oil production. A swap requires us to pay the counterparty if the settlement price exceeds the strike price and the same counterparty is required to pay us if the settlement price is less than the strike price. The objective of the Company's use of derivative financial instruments is to achieve more predictable cash flows in an environment of volatile oil and gas prices and to manage its exposure to commodity price risk. While the use of these derivative instruments limits the downside risk of adverse price movements, such use may also limit the Company's ability to benefit from favorable price movements. The Company may, from time to time, add incremental derivatives to hedge additional production, restructure existing derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company's existing positions.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company's derivative contracts are currently with one counterparty. The Company has netting arrangements with the counterparty that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF MARCH 31, 2011

(UNAUDITED)

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Other Property and Equipment

Other property and equipment such as office furniture and equipment, vehicles, and computer hardware and software are recorded at cost. Costs of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed when incurred. Depreciation is recorded using the straight-line method over the estimated useful lives of three years for computer equipment and five years for office equipment and vehicles. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts.

Revenue Recognition

The Company records revenues from the sales of natural gas and crude oil when they are produced and sold.

Asset Retirement Obligation

The Company follows accounting for asset retirement obligations in accordance with ASC 410, which requires that the fair value of a liability for an asset retirement obligation be recognized in the period in which it was incurred if a reasonable estimate of fair value could be made. The associated asset retirement costs are capitalized as part of the carrying amount of the long-lived asset. The increase in carrying value of a property associated with the capitalization of an asset retirement cost is included in proved oil and gas properties in the consolidated balance sheets. The Company depletes the amount added to proved oil and gas property costs. The future cash outflows associated with settling the asset retirement obligations that have been accrued in the accompanying balance sheets are excluded from the ceiling test calculations. The Company also depletes the estimated dismantlement and abandonment costs, net of salvage values, associated with future development activities that have not yet been capitalized as asset retirement obligations. These costs are included in the ceiling test calculation. Asset retirement obligations incurred are classified as Level 3 (unobservable inputs) fair value measurements. The asset retirement liability is allocated to operating expense using a systematic and rational method. As of March 31, 2011, the Company recorded a net asset of $491,562 and a related liability of $529,506.

The information below reconciles the value of the asset retirement obligation for the periods presented:

	For the Three Months Ended March 31, 2011		For the Year Ended December 31, 2010
Balance, beginning of period	$	507,280	$	-
Liabilities incurred		12,324		478,208
Accretion expense		9,902		28,042
Change in estimate		-		1,030
Balance, end of period	$	529,506	$	507,280

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF MARCH 31, 2011

(UNAUDITED)

NOTE 1 - SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

Share Based Compensation

The Company accounts for share-based compensation in accordance with the provisions of ASC 718— Stock Compensation which requires companies to estimate the fair value of share-based payment awards made to employees and directors, including stock options, restricted stock and employee stock purchases related to employee stock purchase plans, on the date of grant using an option-pricing model. The value of the portion of the award that is ultimately expected to vest is recognized as an expense ratably over the requisite service periods. We estimate the fair value of each share-based award using the Black-Scholes option pricing model. The Black-Scholes model is highly complex and dependent on key estimates by management. The estimates with the greatest degree of subjective judgment are the estimated lives of the stock-based awards and the estimated volatility of our stock price.

Loss per Common Share

Basic earnings (loss) per share is computed based on the weighted average number of common shares outstanding during the period presented. In addition to common shares outstanding, and in accordance with ASC 260 – Earnings per share, diluted loss per share is computed using the weighted-average number of common shares outstanding plus the number of common shares that would be issued assuming exercise or conversion of all potentially dilutive common shares had been issued. Potentially dilutive securities, such as stock grants and stock purchase warrants, are excluded from the calculation when their effect would be anti-dilutive. For the period ended March 31, 2011, outstanding warrants of 22,555,600 have been excluded from the diluted share calculations as they were anti-dilutive as a result of net losses incurred. Accordingly, basic shares equal diluted shares for all periods presented.

NOTE 2 – OIL AND GAS PROPERTIES

In February 2011, the Company closed on the acquisition of oil and gas leases from various private individuals for $1,253,780 in cash and $653,449 in stock in the Grover Field and surrounding area in Weld County, Colorado, and Goshen County, Wyoming.

In March 2011, the Company closed on the acquisition of oil and gas interests located in Laramie County, Wyoming. The purchase price was $6,469,552 cash and $5,798,546 in stock. The Company also closed on two acquisitions of oil and gas leases from various private individuals for a combined $551,519 in cash in Goshen County, Wyoming.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF MARCH 31, 2011

(UNAUDITED)

NOTE 3 – WELLS IN PROGRESS

The following table reflects the net changes in capitalized additions to wells in progress for the periods presented, and includes amounts that were capitalized and reclassified to proved properties in the same period.

	For the Three Months Ended March 31, 2011			For the Year Ended December 31, 2010
Balance, beginning of period	$	1,219,397		$	-
Additions to wells in progress		2,202,438			2,750,499
Reclassifications to proved properties		(1,380,048	)		(1,531,102	)
Balance, end of period	$	2,041,787		$	1,219,397

NOTE 4 - FINANCIAL INSTRUMENTS AND DERIVATIVES

During 2011 and 2010, the Company has entered into various commodity derivative financial instruments intended to hedge against exposure to market fluctuations of oil prices. As of March 31, 2011, the Company had commodity swaps for the following oil volumes:

	Barrels per		Barrels per		Price per
	quarter		Day		Barrel
2011
Second quarter		9,900		110	$	85.97
Third quarter		9,900		110	$	84.95
Fourth quarter		16,000		178	$	91.15

2012
First quarter		9,100		101	$	101.2	0
Second quarter		9,100		101	$	101.2	0
Third quarter		9,200		102	$	101.2	0
Fourth quarter		3,100		100	$	101.2	0

The amount of gain (loss) recognized in income related to our derivative financial instruments was as follows:

	For the Three Months Ended March 31,
	2011			2010
Realized loss on oil contracts	$	(167,284	)	$	-
Loss on commodity price risk management activities	$	( 477,912	)	$	(133,369	)

Unrealized gains and losses resulting from derivatives are recorded at fair value on the consolidated balance sheet and changes in fair value are recognized in the unrealized gain (loss) on risk management activities line on the consolidated statement of operations. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity price risk management activities line on the consolidated statement of operations.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF MARCH 31, 2011

(UNAUDITED)

NOTE 5 - FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company records certain of its assets and liabilities on the balance sheet at fair value. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). A three-level valuation hierarchy has been established to allow readers to understand the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:

●	Level 1	Quoted prices (unadjusted) for identical assets or liabilities in active markets.

●	Level 2	Quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; and model-derived valuations whose inputs or significant value drivers are observable.

●	Level 3	Unobservable inputs that reflect the Company’s own assumptions.

The following describes the valuation methodologies the Company uses for its fair value measurements.

Derivative instruments

The Company determines its estimate of the fair value of derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, and the credit rating of its counterparty. The Company also performs an internal valuation to ensure the reasonableness of third-party quotes.

In evaluating counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. The Company considered that the counterparty is of substantial credit quality and has the financial resources and willingness to meet its potential repayment obligations associated with the derivative transactions.

At March 31, 2011, the types of derivative instruments utilized by the Company included commodity swaps. The oil derivative markets are highly active. Although the Company’s economic hedges are valued using public indices, the instruments themselves are traded with third-party counterparties and are not openly traded on an exchange. As such, the Company has classified these instruments as Level 2.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF MARCH 31, 2011

(UNAUDITED)

NOTE 5 - FAIR VALUE OF FINANCIAL INSTRUMENTS (Continued)

The following table provides a summary of the fair values of assets and liabilities measured at fair value:

	Level 1			Level 2				Level 3				Total
Liability
Derivative Liability		$	—		$	—			$	(2,783,000	)		$	(2,783,000	)
Commodity swap contracts		$	—		$	(876,752	)		$	—			$	(876,752	)
Total liability at fair value		$	—		$	(876,752	)		$	(2,783,000	)		$	(3,659,752	)

The Company did not have any transfers of assets or liabilities between Level 1, Level 2 or Level 3 of the fair value measurement hierarchy during the three months ended March 31, 2011.

At March 31, 2011, the Company’s commodity swap contracts were held with a single counterparty. The Company continually reviews the credit-worthiness of its counterparties. The Company’s derivative instruments are part of master netting agreements, which reduces credit risk by permitting the Company to net settle for transactions with the same counterparty. The Company's derivative liability relates to certain variable conversion rights issued in connection with the Company's convertible notes.

The Company used level 3 inputs to estimate the fair value of common stock used in the acquistition of unproved oil and gas properties during the quarter ended.

NOTE 6 - LOAN AGREEMENTS

Term Notes

The Company entered into three separate loan agreements with Hexagon Investments, LLC (“Hexagon”) during the 2010. All three loans bear annual interest of 15% and mature on September 1, 2012.

Effective January 29, 2010, the Company entered into a $4.5 million loan agreement, with an original maturity date of December 1, 2010. Effective March 25, 2010, the Company entered into a $6.0 million loan agreement, with an original maturity date of December 1, 2010. Effective April 14, 2010, the Company entered into a $15.0 million loan agreement, with an original maturity date of December 1, 2010. All three loan agreements have similar terms, including customary representations and warranties and indemnification, and require the Company to repay the notes with the cash flows from the production of the acquired properties. The loans contain cross collateralization and cross default provisions and are collateralized by mortgages against a portion of the Company’s developed and undeveloped leasehold acreage as well as all related equipment purchased in the Wilke Field, Albin Field, and State Line Field acquisitions. The Company entered into a loan modification agreement on May 28, 2010, which extended the maturity date of the loans to December 1, 2011. In consideration for extending the maturity of the loans, Hexagon received 1 million warrants with an exercise price of $1.50 per share. The loan modification agreements required the Company to issue 1 million five year warrants to purchase common stock at $1.50 per share to Hexagon if the Company did not repay the loans in full by January 1, 2011.

In December 2010, Hexagon extended the maturity to September 1, 2012.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF MARCH 31, 2011

(UNAUDITED)

NOTE 6 – LOAN AGREEMENTS (Continued)

Since the loans were not paid in full by January 1, 2011, the Company issued 1,000,000 additional warrants with an exercise price of $1.50 per share to Hexagon which was valued at approximately $1,600,000, and is being amortized over the remaining term of the loan.

The Company is subject to certain financial and non-financial covenants with respect to the Hexagon loan agreements. As of March 31, 2011, the Company was in compliance with all covenants under the facilities. If any of the covenants are violated, and the Company is unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default and accelerate all principal and interest outstanding.

Convertible Notes Payable

In February 2011, the Company issued in a private placement $8,400,000 aggregate principal amount of three year 8% Senior Secured Convertible Debentures with a group of accredited investors, who are existing shareholders of the Company. Of the proceeds from the sale, $3,000,000 is restricted to acquisition of and drilling activities on specified properties, which were pledged as collateral for the Debentures. The balance of the proceeds are to be used by the Company for working capital. The Debentures are convertible at any time at the holders' option into shares of Recovery Energy common stock at $2.35 per share, subject to certain adjustments, including the requirement to reset the conversion price based upon any subsequent equity offering at a lower price per share amount. Interest on the Debentures is payable quarterly on each May 15, August 15, November 15 and February 15 in cash or at the Company's option in shares of common stock, valued at 95% of the volume weighted average price of the common stock for the 10 trading days prior to an interest payment date. The Company can redeem some or all of the Debentures at any time. The redemption price is 115% of principal plus accrued interest. If the holders of the Debentures elect to convert the Debentures, following notice of redemption, the conversion price will include a make-whole premium equal to the remaining interest through the 18 month anniversary of the original issue date of the Debentures, payable in common stock. T.R. Winston & Company LLC acted as placement agent for the private placement and received $400,000 of Debentures equal to 5% of the gross proceeds from the sale.

The Company calculated the fair value of the conversion feature to be approximately $2,787,000. This amount has been estimated by Management and been accounted for as a discount to the note payable and will be accreted on a straight line basis over the life of the convertible notes payable. During the second quarter the Company intends to have a third party review of its estimate of the fair value of this conversion right and it is likely this estimate may change. Management does not believe any change, however, will be material to its financial position or results of operations. As the conversion adjustment qualifies the instrument as a derivative, the offset was recorded as a derivative liability and will be adjusted quarterly based on its fair value. Any gains or losses on this liability will be recorded within the Statement of Operations. The fair value adjstment between the date of issuance and March 31, 2011 was not significant.

Interest Expense

For the three months ended March 31, 2011, the Company incurred interest expense of approximately $1,692,000, of which approximately $837,000 was non-cash interest expense related to the amortization of the deferred financing costs, and accretion of the convertible notes payable discount.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF MARCH 31, 2011

(UNAUDITED)

NOTE 7 - COMMITMENTS and CONTINGENCIES

Environmental and Governmental Regulation

At March 31, 2011, there were no known environmental or regulatory matters which are reasonably expected to result in a material liability to the Company. Many aspects of the oil and gas industry are extensively regulated by federal, state, and local governments in all areas in which the Company has operations. Regulations govern such things as drilling permits, environmental protection and pollution control, spacing of wells, the unitization and pooling of properties, reports concerning operations, royalty rates, and various other matters including taxation. Oil and gas industry legislation and administrative regulations are periodically changed for a variety of political, economic, and other reasons. As of March 31, 2011, the Company had not been fined or cited for any violations of governmental regulations that would have a material adverse effect upon the financial condition of the Company.

Legal Proceedings

The Company may from time to time be involved in various other legal actions arising in the normal course of business. In the opinion of management, the Company’s liability, if any, in these pending actions would not have a material adverse effect on the financial positions of the Company. The Company’s general and administrative expenses would include amounts incurred to resolve claims made against the Company.

Potential Stock Grants Under Employment/Appointment Agreements

Until May 2010, the employment agreements for our chief executive officer and chief financial officer contained provisions which provided these individuals additional stock grants if the Company achieved certain market capitalization milestones. In May 2010, the employment agreements were modified and our chief executive officer and chief financial officer were no longer entitled to stock grants based on market capitalization milestones.

No shares were issued under these agreements; however the Company recorded approximately $200,000 of expense during the three months ended March 31, 2010.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF MARCH 31, 2011

(UNAUDITED)

NOTE 8 - SHAREHOLDERS’ EQUITY

Common Stock

As of March 31, 2011, the Company had 100,000,000 shares of common stock and 10,000,000 shares of preferred stock authorized, of which 62,483,758 of common shares were issued and outstanding. No preferred shares were issued or outstanding.

During the three months ended March 31, 2011, the Company issued 4,626,889 shares of common stock. The stock issuances were comprised of 2,698,556 shares issued for acquisitions valued at $6,508,395, 40,000 shares issued for services valued at $82,000, 387,000 shares issued as restricted stock grants to employees valued at $1,064,250, and 1,501,333 shares issued in connection with warrant exercises for $2,903,794 of cash.

Temporary Equity

As part of the reverse merger in 2009, 85,000 shares of common stock were issued and outstanding under a lock-up agreement that has terms which may result in the Company reacquiring the shares due to circumstances outside of the Company’s control and therefore the shares are preferential to common shares. The 85,000 shares, which were valued at $172,516, covered by the lock-up agreement were treated as temporary equity and reported separately from other shareholders’ equity. The lock-up period for 42,500 shares ended on September 21, 2010, with the other lock-up period ending on March 21, 2011. As a result, on March 21, 2011, the final 42,500 shares covered under the lock-up agreement were moved to permanent on equity.

Warrants

On January 1, 2011, the Company issued 1 million warrants with an exercise price of $1.50 per share to Hexagon which was valued at approximately $1,600,000.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF MARCH 31, 2011

(UNAUDITED)

NOTE 9 - SHARE BASED COMPENSATION

The Company has not adopted a stock incentive plan for its management team. Each member of the board of directors and the management team was awarded restricted stock grants in their respective appointment or employment agreements.

The Company accounts for stock based compensation arrangements in accordance with the provisions of ASC 718 Compensation – Stock Compensation. ASC 718 requires measurement and recording to the financial statements of the costs of employee services received in exchange for an award of equity instruments based on the grant-date fair value of the award, recognized over the period during which an employee is required to provide services in exchange for such award. The Company implemented ASC 718 effective March 6, 2009.

During the three months ended March 31, 2011, the Company granted 387,000 shares of restricted common stock to employees of which 54,000, 116,500, 141,500, and 75,000 shares vest during the years ended December 31, 2011, 2012, 2013, and 2014, respectively. The fair value of these share grants was calculated to be approximately $1,064,000.

The Company recognized stock compensation expense of approximately $546,000 and $906,000 for the three months ended March 31, 2011 and 2010, respectively.

A summary of restricted stock grant activity for the three months ended March 31, 2011, and the year ended December 31, 2010 is presented below:

	Shares
Balance outstanding at January 1, 2010		1,484,200
Granted		7,458,987
Vested		-
Balance outstanding at December 31, 2010		8,943,187
Granted		387,000
Vested		(175,000	)
Balance outstanding at March 31, 2011		9,155,187

Total unrecognized compensation cost related to non-vested stock granted was $1,820,443 as of March 31, 2011. The cost at March 31, 2011 is expected to be recognized over a weighted-average remaining service period of 0.23 years.

RECOVERY ENERGY, INC.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

AS OF MARCH 31, 2011

(UNAUDITED)

NOTE 10 – SUBSEQUENT EVENTS

On April 11, 2011, our president and chief financial officer resigned. In connection with his resignation the Company entered into a separation agreement with him pursuant to which he will receive as severance one year's base salary of $225,000, a bonus for 2010 in the same amount, if any, paid to our chief executive officer, as determined by our compensation committee of the board of directors in its sole discretion, and will retain his 1,925,000 unvested shares of our common stock, which will vest in four equal installments of 481,250 shares quarterly commencing July 15, 2011.

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q includes “forward-looking statements” as defined by the Securities and Exchange Commission, or SEC. All statements, other than statements of historical facts, included in this Form 10-Q that address activities, events or developments that we expect, believe or anticipate will or may occur in the future are forward-looking statements. These forward-looking statements are based on assumptions which we believe are reasonable based on current expectations and projections about future events and industry conditions and trends affecting our business. However, whether actual results and developments will conform to our expectations and predictions is subject to a number of risks and uncertainties that, among other things, could cause actual results to differ materially from those contained in the forward-looking statements, including without limitation the Risk Factors set forth in our Annual Report on Form 10-K for the year ended December 31, 2010, including the following:

	•		Our ability to maintain adequate liquidity in connection with low oil and gas prices;

	•		The changing political environment in which we operate;

	•		Our ability to obtain, or a decline in, oil or gas production;

	•		A decline in oil or gas prices;

	•		Our ability to increase our natural gas and oil reserves;

	•		Incorrect estimates of required capital expenditures;

	•		The amount and timing of capital deployment in new investment opportunities;

	•		The volumes of production from our oil and gas development properties, which may be dependent upon issuance by federal, state, and tribal governments, or agencies thereof, of drilling, environmental and other permits, and the availability of specialized contractors, work force, and equipment;

	•		Our future capital requirements and availability of capital resources to fund capital expenditures;

	•		Our ability to successfully integrate and profitably operate any future acquisitions;

	•		Increases in the cost of drilling, completion and gas collection or other costs of production and operations;

	•		The possibility that we may be required to take impairment charges to reduce the carrying value of some of our long-lived assets when indicators of impairment emerge;

	•		Numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and actual future production rates and associated costs;

	•		Our ability to remedy any deficiencies that may be identified in the review of our internal controls;

	•		The credit worthiness of third-parties which we enter into business agreements with;

	•		General economic conditions, tax rates or policies, interest rates and inflation rates;


	•		Changes in or compliance with laws and regulations, particularly those relating to taxation, safety and protection of the environment;

	•		Weather, climate change and other natural phenomena;

	•		Industry and market changes, including the impact of consolidations and changes in competition;

	•		The effect of accounting policies issued periodically by accounting standard-setting bodies;

	•		The actions of third party co-owners of interests in properties in which we also own an interest;

	•		The cost and effects on our business, including insurance, resulting from terrorist actions or natural disasters and responses to such actions or events;

	•		The volatility of our stock price; and

	•		The outcome of any current or future litigation or similar disputes and the impact on any such outcome or related settlements.

We also may make material acquisitions or divestitures or enter into financing transactions. None of these events can be predicted with certainty and the possibility of their occurring is not taken into consideration in the forward-looking statements.

New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. We assume no obligation to update publicly any such forward -looking statements, whether as a result of new information, future events, or otherwise.

Overview

Recovery Energy Inc. is a Denver based independent oil and gas company engaged in the acquisition, drilling and production of oil and natural gas properties and prospects within the DJ Basin. Our business strategy is designed to create maximum shareholder value by leveraging the knowledge, expertise and experience of our management team along with that of our operating partners.

Recent Developments

In February 2011, the Company closed on the acquisition of oil and gas leases from various private individuals on approximately 1,700 leasehold acres in the Grover Field and surrounding area in Weld County, Colorado, and approximately 6,600 net acres in Goshen County, Wyoming. The purchase price was $1,253,780 in cash and $653,449 in common stock.

In March 2011, the Company closed on the acquisition of oil and gas interests of approximately 8,060 net acres located in Laramie County, Wyoming. The purchase price was $6,469,552 cash and $5,798,546 in stock.

In March 2011, the Company entered into a modification of its swap agreement whereby Shell extended the company $1,000,000 of unsecured credit. Additionally, the Company entered into an additional commodity swap for 100 barrels per day from November 2011 through October 2012 at a price of $100.20 per barrel.

In March 2011, the Company closed on the acquisition of oil and gas leases from various private individuals for $390,000 in cash on approximately 651 net acres in Goshen County, Wyoming.

In March 2011, the Company closed on the acquisition of oil and gas leases from various private individuals for $161,519 in cash on approximately 640 net acres in Goshen County, Wyoming.

In March 2011, the Company issued 1,501,333 shares of common stock upon the exercise of outstanding warrants to purchase common stock. The Company received gross proceeds of approximately $2,315,000.

Liquidity and Capital Resources

2011 Capital Budget

We are maintaining our previously announced 2011 capital expenditure budget of approximately $20 million, which is allocated to oil and gas activities and acquisitions in the DJ Basin in Wyoming, Nebraska and Colorado targeting the conventional Dakota ‘D’ sand and Muddy ‘J’ sand targets as well as the unconventional Niobrara shale. We have spent approximately $8.5 million for acquisitions during the first quarter of 2011. In addition to acquisitions, we have spent approximately $2.8 million in drilling capital expenditures on 2 gross (2 net) conventional wells and completion activities on 3 gross (3 net) conventional wells during the first quarter for 2011. We anticipate resuming the drilling of conventional targets after we have assessed the results from the current drilling program. Additionally, we have allocated $7 million to $9 million to the drilling and completion of 2 gross (0.8 net) Recovery-operated Niobrara carried wells in a joint venture with TRW Exploration. We expect to have a non-operating working interest ranging from 25% to 50% in several wells drilled by the operator in the Grover Field area in 2011. We estimate the completed cost for each well to be between $1,000,000 and $4,000,000 and we would be required to fund our prorate portion of each well or be subject to a non-consent penalty. We cannot predict how many well proposals we will receive.

Our 2011 capital expenditure budget is subject to various factors, including market conditions, oilfield services and equipment availability, commodity prices and drilling results. While we continue to explore opportunities to expand our acreage position, our current budget is allocated to drilling and completing wells. Any leasehold acquisitions that we choose to pursue would require us to adjust our budget. Results from the wells identified in the capital budget may lead to additional adjustments to the capital budget as the cash flow from the wells could provide additional capital which we may use to increase our capital budget.

Other factors that could cause us to further increase our level of activity and adjust our capital expenditure budget include a reduction in service and material costs, the formation of joint ventures with other exploration and production companies, the divestiture of non-strategic assets, a further improvement in commodity prices or well performance that exceeds our forecasts, any of which could positively impact our operating cash flow. Factors that could cause us to reduce level of activity and adjust our capital budget include, but are not limited to, increases in service and materials costs, reductions in commodity prices or under-performance of wells relative to our forecasts, any of which could negatively impact our operating cash flow.

Our 2011 drilling program is designed to provide flexibility in identifying suitable well locations and in the timing and size of capital investment. We anticipate funding this 2011 capital program through a combination of existing working capital, operating cash flows, cash contributions from our joint venture participants, and by issuing additional equity or debt securities.

We anticipate that our operating cash flows will continue to increase as additional wells are drilled and placed on production. The addition of successfully completed Niobrara wells developed under our Joint Venture could provide significant operating cash flows. If we are able to drill and complete our wells as anticipated and they produce at rates similar to those generated by our existing wells, we would expect our production rates and operating cash flows to grow as we move through 2011.

We cannot give assurances that our working capital on hand, our cash flow from operations or any available borrowings will be sufficient to fund our anticipated capital expenditures. If our existing and potential sources of liquidity through operating cash flows and cash contributions from joint venture participants are not sufficient to undertake our planned capital expenditures, we may be required to alter our drilling program, pursue additional joint ventures with third parties, sell interests in one or more of our properties or sell common shares or debt securities. If we are not successful in obtaining sufficient funding or completing an alternative transaction on a timely basis on terms acceptable to us, we would be required to curtail our expenditures or restructure our operations, and we would be unable to implement our planned exploration and drilling program.

Capital Resources

We believe that we have sufficient liquidity and capital resources to continue our current operations. Currently the majority of our cash flows from operations are applied to the principal and interest of our loans. We may also consider additional offerings of securities to develop our 152,000 gross (131,000 net) undeveloped acres. Although we believe that we would be able to secure additional financing if required, we can provide no assurance that we will be able to do so or what the terms of any additional financing would be.

Information about our financial position is presented in the following table:

	March 31, 2011		December 31, 2010
Financial Position Summary
Cash and cash equivalents	$	2,111,340	$	5,528,744
Working capital	$	2,297,607	$	4,436,365
Balance outstanding on term notes and convertible notes payable	$	25,755,640	$	20,438,682
Common stock subject to redemption rights and shareholders’ equity	$	51,809,323	$	44,256,602
Ratios
Debt to total capital ratio		33%		32%
Total debt to equity ratio		50%		46%

During the quarter ended March 31, 2011, our working capital decreased to $2,297,607 from $4,436,365 at December 31, 2010. The lower working capital and cash position is primarily the result of approximately $10,100,000 in capital raised during the three months ended March 31, 2011, offset by approximately $10,700,000 in capital additions, as well as the net decrease in operating assets and liabilities of approximately $1,700,000. Our decrease in net operating assets and liabilities is primarily due to an increase in accounts receivable of approximately $800,000 and an increase in restricted cash of approximately $800,000.

	Three Months Ended March 31,
	2011		2010
Cash provided by (used in):
Operating activities	$	(2,440,205)	$	(195,332)
Investing activities		(10,711,902)		(10,362,271)
Financing activities		9,734,703		10,621,250

Net change in cash		(3,417,404)		63,647

During the three month periods ended March 31, 2011 and 2010, net cash used in operating activities was $2,440,205 and $195,332, respectively. The primary changes in operating cash during the three months ended March 31, 2011 was $3,743,186 of net loss, adjusted for non-cash charges of $1,075,930 of depreciation, depletion and amortization expenses (“DD&A”) and accretion expense, $546,529 of stock-based compensation, and $837,376 of amortization of deferred financing costs, offset by increases in accounts receivable of $788,431 and restricted cash of $848,280.

During the three month periods ended March 31, 2011 and 2010, net cash used by investing activities was $10,711,902 and $10,362,271. The primary changes in investing cash during the three months ended March 31, 2011 was $8,416,874 related to our acquisitions of unproved acreage and $2,281,487 in drilling capital expenditures.

During the three month periods ended March 31, 2011 and 2010, net cash provided by financing activities was $9,734,703 and $10,621,250. The primary changes in financing cash during the three months ended March 31, 2011 was net proceeds from the exercise of warrants for $2,129,801 and the issuance of convertible notes payable for $8,000,000, offset by debt repayments of $395,098.

Loan Agreements

The Company entered into three separate loan agreements with Hexagon Investments, LLC (“Hexagon”) during the 2010. All three loans bear annual interest of 15%, and mature on September 1, 2012.

In December 2010, Hexagon extended the maturity to September 1, 2012.

We are subject to certain financial and non-financial covenants with respect to the Hexagon loan agreements. As of March 31, 2011, we were in compliance with all covenants under the facilities. If any of the covenants are violated, and the Company is unable to negotiate a waiver or amendment thereof, the lender would have the right to declare an event of default and accelerate all principal and interest outstanding.

As of March 31, 2011, the outstanding balance on the loan agreements was approximately $20,000,000, approximately $270,000 of which was classified as a current liability.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements.

Oil and Gas Properties & Strategy

We have developed and acquired an oil and natural gas base of proved reserves, as well as a portfolio of development drilling and exploratory drilling opportunities of high-impact conventional and non-conventional prospects with an emphasis on multiple producing horizons and the Niobrara shale resource play. We believe these prospects offer repeatable success allowing for meaningful production and reserve growth. Our acquisition and exploration pursuits of oil and natural gas properties are principally located in Colorado, Nebraska, and Wyoming. Since January 1, 2010 we have acquired or developed 19 producing wells. We currently own interests in approximately 155,000 gross (133,000 net) leasehold acres, of which 152,000 gross (131,000 net) acres are classified as undeveloped acreage and all of which are located in Colorado, Wyoming and Nebraska in the DJ Basin. We intend to continue to evaluate and invest in acquisitions and internally generated prospects. It is our long-term goal to maximize our DJ Basin acreage position through development drilling of our conventional horizons as well as development of our Niobrara shale potential.

We have invested, and intend to continue to invest, primarily in oil and natural gas interests, including producing properties, prospects, leases, wells, mineral rights, working interests, royalty interests, overriding royalty interests, net profits interests, production payments, farm-ins, drill to earn arrangements, partnerships, easements, rights of way, licenses and permits, in the DJ Basin in Colorado, Nebraska, and Wyoming.

It is our belief that the exploration and production industry’s most significant value creation occurs through the drilling of successful development wells and the enhancement of oil recovery in mature fields given appropriate economic conditions. Our goal is to create significant value while maintaining a low cost structure. To this end, our business strategy includes the following elements:

Participation in development prospects in known producing basins. We pursue prospects in known producing onshore basins where we can capitalize on our development and production expertise. We intend to operate the majority of our properties and evaluate each prospect based on its geological and geophysical merits.

Negotiated acquisitions of properties. We acquire producing properties based on our view of the pricing cycles of oil and natural gas and available exploration and development opportunities of proved, probable and possible reserves.

Retain Operational Control and Significant Working Interest. In our principal development targets, we typically seek to maintain operational control of our development and drilling activities. As operator, we retain more control over the timing, selection and process of drilling prospects and completion design, which enhances our ability to maximize our return on invested capital and gives us greater control over the timing, allocation and amounts of our capital expenditures. We have continued to maintain high working interest in our DJ Basin properties which maximizes our exposure to generated cash flows and increases in value as the properties are developed. With operational control, we can also schedule our drilling program to satisfy most of our lease stipulations and continue to put our acreage into “held by production” status, thus eliminating expirations. The majority of our acreage is contiguous which will permit efficiencies in drilling and production operations.

Leasing of prospective acreage. In the course of our business, we identify drilling opportunities on properties that have not yet been leased. At times, we take the initiative to lease prospective acreage and we may sell all or any portion of the leased acreage to other companies that want to participate in the drilling and development of the prospect acreage.

Controlling Costs. We maximize our returns on capital by minimizing our expenditures on general and administrative expenses. We also minimize initial capital expenditures on geological and geophysical overhead, seismic data, hardware and software by partnering with cost efficient operators that have already invested capital in such. Historically, we also outsourced some of our geological, geophysical, reservoir engineering and land functions in order to help reduce capital requirements. We recently brought many of these functions in-house to provide us with greater ability to maximize the value of our growing leasehold position.

We use commodity price hedging instruments to reduce our exposure to oil and natural gas price fluctuations and to help ensure that we have adequate cash flow to fund our debt service costs and capital programs. From time to time, we will enter into futures contracts, collars and basis swap agreements, as well as fixed price physical delivery contracts. We intend to use hedging primarily to manage price risks and returns on certain acquisitions and drilling programs. Our policy is to consider hedging an appropriate portion of our production at commodity prices we deem attractive. In the future we may also be required by our lenders to hedge a portion of production as part of any financing.

Marketing and Pricing

We derive revenue principally from the sale of oil and natural gas. As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil and natural gas. We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts. The market price for oil and natural gas is dictated by supply and demand, and we cannot accurately predict or control the price we may receive for our oil and natural gas.

Our revenues, cash flows, profitability and future rate of growth will depend substantially upon prevailing prices for oil and natural gas. Prices may also affect the amount of cash flow available for capital expenditures and our ability to borrow money or raise additional capital. Lower prices may also adversely affect the value of our reserves and make it uneconomical for us to commence or continue production levels of oil and natural gas. Historically, the prices received for oil and natural gas have fluctuated widely. Among the factors that can cause these fluctuations are:

●		changes in global supply and demand for oil and natural gas;
●		the actions of the Organization of Petroleum Exporting Countries, or OPEC;
●		the price and quantity of imports of foreign oil and natural gas;
●		acts of war or terrorism;
●		political conditions and events, including embargoes, affecting oil-producing activity;
●		the level of global oil and natural gas exploration and production activity;
●		the level of global oil and natural gas inventories;
●		weather conditions;
●		technological advances affecting energy consumption; and
●		the price and availability of alternative fuels.

From time to time, we will enter into hedging arrangements to reduce our exposure to decreases in the prices of oil and natural gas. Hedging arrangements may expose us to risk of significant financial loss in some circumstances including circumstances where:

●		our production and/or sales of natural gas are less than expected;
●		payments owed under derivative hedging contracts come due prior to receipt of the hedged month’s production revenue; or
●		the counter party to the hedging contract defaults on its contract obligations.

In addition, hedging arrangements may limit the benefit we would receive from increases in the prices for oil and natural gas. We cannot assure you that any hedging transactions we may enter into will adequately protect us from declines in the prices of oil and natural gas. On the other hand, where we choose not to engage in hedging transactions in the future, we may be more adversely affected by changes in oil and natural gas prices than our competitors who engage in hedging transactions.

Recent Performance

Following are summary comments of our performance in several key areas during the quarter ended March 31, 2011.

	●		Average Daily Production
			During the quarter ended March 31, 2011, average daily net production was 281 BOPD net compared to average daily net production of 100 BOPD for the quarter ended March 31, 2010. This increase is primarily attributable to acquisitions of the Palm and State Line fields which the Company acquired subsequent to March 31, 2010.

	●		Oil and Gas Sales
			During the quarter ended March 31, 2011, net oil and gas sales were $1,910,643. Our average oil and gas price received was $86.49 per barrel of oil and $4.04 per Mcf of gas.

	●		Cash Flow from Operations
			During the quarter ended March 31, 2011, we used $2,440,205 in cash from operations.

Results of Operations

For the Three Months Ended March 31, 2011 compared to the Three Months Ended March 31, 2010

The Company reported a net loss for the three months ended March 31, 2011 of approximately $3,743,000 compared to a net loss of approximately $2,821,000 for the same period in 2010. Oil and gas revenues increased from approximately $623,000 in the first quarter of 2010 to approximately $1,911,000 in the first quarter of 2011. Our production volume on a BOE basis increased 185% from 8,897 BOE during the first quarter of 2010 to 25,328 BOE during the first quarter of 2011. This increase is primarily attributable to the Palm and State Line acquisitions that the Company completed subsequent to March 31, 2010. In addition, we realized increased prices during the first quarter of 2011 versus the first quarter of 2010. Oil price realization increased by 24% to $86.49 per barrel for the first quarter of 2011, compared to $69.98 per barrel for the same period in 2010. This increase in price realization during the first quarter of 2011 was partially offset by a realized loss on hedges of approximately $167,000 and a non-cash charge of approximately $478,000 for the change in value of commodity derivatives that we use to mitigate our exposure to oil price volatility. There was no realized gain or loss for such risk management activities during the first quarter of 2010, but the Company did experience a non-cash charge of approximately $133,000 for the change in value of commodity derivatives during the same period.

Oil and Gas Revenue and Production

During the three months ended March 31, 2011, as compared to the same period in 2010, oil production volumes increased from 8,897 barrels of oil to 20,833 barrels of oil, or 134%, primarily due to the Palm and State Line acquisitions which the Company completed subsequent to March 31, 2010. Natural gas production increased from zero during to the three months ended March 31, 2010 to 26,969 Mcf during the same period in 2011. Oil and natural gas revenues increased by approximately $1,288,000, or 207%, compared to the first quarter of 2010, primarily due to the Palm and Sate Line acquisitions and, to a lesser extent, increased realized prices in 2011 compared to 2010. The increase in oil and gas revenue was 89% attributable to the increase in production volumes and 11% attributable to the increase in realized commodity prices.

	Three Months Ended
	March 31, 2011
	Volume		Average Price
Product:
Oil (Bbls)		20,833	$	86.49
Natural Gas (Mcf)		26,969	$	4.04

Average daily net production was 281 BOPD for the quarter ended March 31, 2011.

Price Risk Management Activities

We recorded a net loss on our derivative contracts that do not qualify for cash flow hedge accounting of $(477,912) for the three month period ended March 31, 2011, compared to a net loss of $(133,369) for the three month period ended March 31, 2010. These amounts represent an unrealized non-cash loss which represents a change in the fair value of our mark-to-market derivative instruments. We realized a loss on our derivative contracts that do not qualify for cash flow hedge accounting of $292,805 for the quarter ended March 31, 2011. We did not realize any hedge gain or loss for the three month period ended March 31, 2010.

Oil and gas production expenses, depreciation, depletion and amortization

	Three Months Ended March 31,
	2011
	(per BOE)
Average price	$	75.44

Production costs		17.65
Production taxes		7.99
Depletion and amortization		42.20

Total operating costs		67.84


Gross margin	$	7.60

Gross margin percentage		10.10	%

General and administrative expenses

General and administrative expenses were $1,600,594 for the quarter ended March 31, 2011. Our general and administrative expenses for the quarter included approximately $418,000 in professional fees, and approximately $546,000 in non-cash compensation expense.

CONTRACTED VOLUMES

Changes in the market price of oil can significantly affect our profitability and cash flow. We have entered into various derivative instruments to mitigate the risk associated with downward fluctuations in oil prices. These derivative instruments consist of swaps. The duration and size of our various derivative instruments varies, and depends on our view of market conditions, available contract prices and our operating strategy.

Our outstanding derivative instruments as of March 31, 2011 are summarized below:

	Barrels per		Barrels per		Price per
	quarter		Day		Barrel
2011
Second quarter		9,900		110	$	85.97
Third quarter		9,900		110	$	84.95
Fourth quarter		16,000		178	$	91.15

2012
First quarter		9,100		101	$	101.2	0
Second quarter		9,100		101	$	101.2	0
Third quarter		9,200		102	$	101.2	0
Fourth quarter		3,100		100	$	101.2	0

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Not required for smaller reporting companies.

Item 4T. Controls and Procedures

As required by Rule 13a-15 under the Securities Exchange Act of 1934 (the "1934 Act"), as of March 31, 2011, we carried out an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures. This evaluation was carried out by our Chief Executive Officer and Interim Principal Financial Officer, who concluded, that our disclosure controls and procedures were effective as of March 31, 2011. Disclosure controls and procedures are controls and other procedures that are designed to ensure that information required to be disclosed in our reports filed or submitted under the Securities Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission's rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed in our reports filed under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and our principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

For the quarter ended March 31, 2011, the departure of our Chief Financial Officer subsequent to the end of the quarter resulted in a material change to our internal control over financial reporting. As a result of this change, the Company engaged an accounting and financial reporting expert on a consulting basis to assist in the preparation of the quarter closing process and financial reporting process. We believe that with the addition of this consultant our internal control over financial reporting has continued to operate effectively.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

PART II - OTHER INFORMATION

Item 1. Legal Proceedings.

Currently we are not aware of any litigation pending or threatened by or against the Company.

Item 1A. Risk Factors.

There have been no material changes in our Risk Factors from those reported in Item 1A of Part I of our 2010 Annual Report on Form 10-K filed with the Securities and Exchange Commission, which we incorporate by reference herein.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

All unregistered issuances of equity securities during the period covered by this report have been previously included in Current Reports on form 8-K.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Submission of Matters to a Vote of Security Holders.

None.

Item 5. Other Information.

None

Item 6. Exhibits and Reports of Form 8-K.

Exhibits

31.1 Certifications pursuant to Section 302 of Sarbanes Oxley Act of 2002

31.2 Certifications pursuant to Section 302 of Sarbanes Oxley Act of 2002

32.1 Certifications pursuant to Section 906 of Sarbanes Oxley Act of 2002

32.2 Certifications pursuant to Section 906 of Sarbanes Oxley Act of 2002

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, the registrant caused this amended report to be signed on its behalf by the undersigned, thereunto duly authorized.

	Recovery Energy, Inc.

Date: May 16, 2011	By:	/s/ Roger A Parker
		Roger A Parker
		Chief Executive Officer and Interim Principal Financial Officer

Date: May 16, 2011	By:	/s/ Christopher R. Barber
		Christopher R. Barber
		Interim Principal Accounting Officer

LILIS ENERGY, INC. - FORM 10-Q - May 16, 2011

Attached files

LILIS ENERGY, INC. Reports